WO2009134902A1 - Système et procédé pour l’utilisation de capsules aplatissables à actionnement par pression, suspendues dans un fluide à dilatation thermique dans un espace de confinement souterrain - Google Patents

Système et procédé pour l’utilisation de capsules aplatissables à actionnement par pression, suspendues dans un fluide à dilatation thermique dans un espace de confinement souterrain Download PDF

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Publication number
WO2009134902A1
WO2009134902A1 PCT/US2009/042137 US2009042137W WO2009134902A1 WO 2009134902 A1 WO2009134902 A1 WO 2009134902A1 US 2009042137 W US2009042137 W US 2009042137W WO 2009134902 A1 WO2009134902 A1 WO 2009134902A1
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WO
WIPO (PCT)
Prior art keywords
pressure
recited
collapsing
capsules
containment space
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PCT/US2009/042137
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English (en)
Inventor
Daniel L. Bour
Original Assignee
Altarock Energy, Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Altarock Energy, Inc. filed Critical Altarock Energy, Inc.
Publication of WO2009134902A1 publication Critical patent/WO2009134902A1/fr

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/1208—Packers; Plugs characterised by the construction of the sealing or packing means

Definitions

  • the present application is directed to systems and methods for use of pressure actuated collapsing capsules suspended in a thermally expanding fluid.
  • geothermal wells are completed in porous geothermal formations having naturally high permeability and which contain heated brine and/or steam in relative close proximity to the surface of the earth. These hydrothermal formations are found in a number of locations around the world.
  • HDR hot dry rock
  • Enhanced geothermal systems (EGS) are used to extract thermal energy from deep HDR formations exhibiting low permeability.
  • Most HDR formations grow hotter with increasing depth, and in a related aspect, it is advantageous to isolate zones deep in the formation that generate the most heat.
  • EGS wells completed in deep granite basement rock having in situ temperatures ranging from 15O 0 C to greater than 35O 0 C are capable of producing large quantities of thermal energy.
  • Drilling and completion of oil and gas wells and geothermal wells involves forming a subterranean wellbore by rotating an earth boring bit into an earth formation as weight is applied to the bit.
  • the drilled wellbore is normally lined with a string of tubulars known as casing and the well is completed by pumping cement into the annulus between the casing and the wellbore wall.
  • the casing string is often cemented at the bottom.
  • fluid is often trapped in the annulus between the casing string and the wellbore wall or between two casing strings. Trapped annular fluid thermally expands when the wellbore is heated during drilling, production and other well operations. The thermal expansion of trapped annular fluid can cause annular pressure build-up (APB) and result in collapse of the casing string.
  • APIB annular pressure build-up
  • Expandable or inflatable packers have also been used in the oil and gas and geothermal industries for well related operations such as zone isolation and formation treating. Expandable packers are used to block the flow of fluids through the annular spaces within the wellbore. Expandable packers are typically filled with a material such as cement, water, or drilling fluid to inflate an expandable packer element. The cement eventually hydrates to form a hard, solid material. In order to remove the packer, the cement and expandable packer must be drilled out. For some applications, it is desirable to both inflate and subsequently deflate a packer once a given operation within a well is completed.
  • a material such as cement, water, or drilling fluid to inflate an expandable packer element.
  • the cement eventually hydrates to form a hard, solid material.
  • the cement and expandable packer In order to remove the packer, the cement and expandable packer must be drilled out. For some applications, it is desirable to both inflate and subsequently deflate a packer once a
  • a filler material consisting of a liquid such as water, drilling fluid, oil, and other downhole fluids may be used for such an operation.
  • a liquid such as water, drilling fluid, oil, and other downhole fluids
  • the packer is exposed to an increase in temperature the thermal expansion of the liquid water or other downhole fluids within the packer may cause a pressure increase within the packer. This pressure increase, if sufficiently large, could lead to either the rupture of the inflatable element of the packer and/or the crushing of elements inside the packer.
  • a system comprises a subterranean pressured fluid receiving containment space located in a wellbore of a subterranean well and a pressured operating fluid filling at least a portion of the containment space.
  • the pressured operating fluid comprises a mixture of substantially incompressible liquid and pressure actuated collapsing capsules. At least a portion of the pressure actuated collapsing capsules implode as pressure in the containment space exceeds a predetermined limit.
  • FIG. 1 illustrates an exemplary system for protecting a subterranean containment space in a subterranean well or formation from over-pressure according to one embodiment
  • FIG. 2A illustrates an exemplary pressured operating fluid according to one embodiment
  • FIG. 2B illustrates exemplary pressure actuated collapsing capsules according to one embodiment
  • FIG. 3 illustrates an exemplary system for protecting a subterranean containment space in an annulus of a subterranean well from over-pressure according to one embodiment
  • FIGS. 4A through 4F illustrate an exemplary system for protecting a subterranean containment space in the annulus of a subterranean well from over-pressure according to another embodiment
  • FIGS. 5A through 5E illustrate an exemplary system for protecting a downhole packer from over-pressure according to one embodiment
  • FIG. 6 illustrates an exemplary system for protecting a subterranean containment space in a geothermal well from over-pressure according to one embodiment.
  • subterranean wells including, but not limited to, geothermal wells, oil wells, gas wells, water wells, injection wells or any other well known in the art for producing or injecting fluids.
  • FIG. 1 illustrates an exemplary system for protecting a subterranean containment space 106 in a subterranean well 102 or formation 100 from over-pressure according to one embodiment.
  • the subterranean well 102 may be a geothermal well, oil well, gas well, water well, injection well or any other well known in the art.
  • subterranean pressured fluid receiving containment spaces 106 may form in the wellbore 104 or in the subterranean formation 100.
  • a subterranean containment space 106 such as a downhole packer may be introduced into the subterranean well 102 in an annulus between the production conduit 110 and the casing string 112 or in an annulus 1 14 between the casing string 112 and the wellbore wall 116.
  • a subterranean containment space 106 may form in the annulus 1 14 during a primary well operation such as, cementing of the casing string 112.
  • Subterranean containment spaces 106 may also be naturally occurring voids or cavities in the subterranean formation 100. Downhole fluids may become trapped in subterranean containment spaces 106 during drilling, completion, production and other well operations. If the subterranean well 102 including the wellbore wall 116 and/or fluids within the wellbore 104 are heated during well operations, trapped fluids will thermally expand and pressurize the subterranean containment spaces 106. Thermally expanding downhole fluids can damage the subterranean well 102 and/or elements within the well 102 including, but not limited to. well casing, well liners, well packers, production conduit, downhole tools and other downhole tubulars within the wellbore 104. Thermally expanding downhole fluids can also cause damage to the subterranean formation 100 by propagating undesired fractures within the formation 100.
  • subterranean containment spaces 106 are at least partially filled with pressured operating fluid 108 having a mixture of substantially incompressible liquid and pressure actuated collapsing capsules.
  • the pressure actuated collapsing capsules rupture, implode or collapse when pressure in the subterranean containment space 106 exceeds a predetermined limit, thus compensating for the thermal expansion of the liquid in the containment space 106 and preventing over-pressure from damaging the subterranean well 102.
  • the pressured operating fluid 108 may also be pumped or circulated into a plurality of laterally or vertically arranged subterranean zones 120, 122 in the formation 100 to protect the formation from undesired fracture propagation.
  • Containment spaces 106 in the well 100 and the formation 100 may be partially or fully filled with pressured operating fluid 108 by pumping or circulating the pressured operating fluid 108 into wellbore 104 through the production conduit 110, the casing string 112, or the annulus 114 between the casing string 1 12 and the wellbore wall 116.
  • FIG. 2A illustrates an exemplary pressured operating fluid 30 comprising a mixture of substantially incompressible liquid 32 and pressure actuated collapsing capsules 32 according to one embodiment.
  • the pressure actuated collapsing capsules 34 are suspended in the substantially incompressible liquid 32.
  • a viscosifying agent may be added to the pressured operating fluid 30 to aid in the suspension of the pressure actuated collapsing capsules 34.
  • the viscosifying agent may be an organic polymer such as hydro ethyl cellulose, hydropropyl guar, guar gum, and/or any other compatible organic polymer capable of aiding in the suspension of the pressure actuated collapsing capsules 34.
  • the viscosifying agent may also be an inorganic material such as fumed silica, bentonite, or attapulgite. Weighting materials such as barite or hausmanite may also be added to the pressured operating fluid 30 to modify the density of the fluid.
  • the pressured operating fluid 30 comprising a mixture of substantially incompressible liquid 32 and pressure actuated collapsing capsules 34 is designed to accommodate thermal expansion of liquid in a subterranean containment space, including but not limited to, an expandable bladder of a well packer, an annulus between the casing string and the wellbore wall, an annulus between the production conduit and the casing string, an annulus between two casing strings, a fracture in the subterranean formation or any other downhole tubular, downhole tool, or void in a subterranean well or formation capable of containing liquid.
  • a subterranean containment space including but not limited to, an expandable bladder of a well packer, an annulus between the casing string and the wellbore wall, an annulus between the production conduit and the casing string, an annulus between two casing strings, a fracture in the subterranean formation or any other downhole tubular, downhole tool, or void in a subterranean well or formation capable of
  • the substantially incompressible liquid 32 component of the pressured operating fluid 30 may be selected based on the specific application of the pressured operating fluid 30 and/or the downhole fluids present in the well such as, drilling fluids and production fluids.
  • the substantially incompressible liquid 32 may comprise water.
  • the substantially incompressible liquid 32 may also comprise one or more components that make up a drilling fluid present in the well to maintain compatibility between the pressured operating fluid 30 and the drilling fluid.
  • the substantially incompressible liquid 32 may comprise the drilling fluid or a competent thereof such as the base oil.
  • the substantially incompressible liquid 32 may also comprise mineral oil and/or synthetic oil.
  • the substantially incompressible liquid 32 may comprise various concentrations of potassium chloride brine, sodium chloride brine, production brine and/or other substantially incompressible liquid that is compatible with downhole fluids present in the subterranean well.
  • pressure actuated collapsing capsules 34 are designed to rupture, implode or collapse at a predetermined pressure during the ⁇ nal expansion of the substantially incompressible liquid 32.
  • the pressure actuated collapsing capsules 34 may be of substantially fixed volume or they may have variable volumes within the substantially incompressible liquid 32.
  • the pressure actuated collapsing capsules 34 may also be partially or fully filled with gas 38.
  • the gas 38 may be air or an inert gas such as, nitrogen or argon to prevent chemical reaction with downhole fluids after collapse of the pressure actuated collapsing capsules 34.
  • the gas 38 may also be one or more gases present in the subterranean well such as nitrogen, methane or other hydrocarbon gases.
  • the pressure actuated collapsing capsules 34 may be substantially void of gas.
  • the pressure actuated collapsing capsules 34 may be manufactured to have a predetermined collapse pressure.
  • the pressure actuated collapsing capsules 34 may also be a waste byproduct which have non-uniform or graduated collapse pressures.
  • the pressure actuated collapsing capsules 34 may be hollow and encased in a frangible material 36.
  • the pressure actuated collapsing capsules 34 may be spherical, cratered or ellipsoidal. Hollow microspheres, because of their spherical form, can have a high isotropic compressive strength and are therefore well suited for applications that require high collapse pressures.
  • the pressure actuated collapsing capsules 34 may be designed to have a substantially uniform collapse pressure, such that the majority of pressure actuated collapsing capsules 34 fail or collapse at the same pressure.
  • the pressure actuated collapsing capsules 34 may also be designed to have non-uniform or variable collapse pressures.
  • the frangible material 36 may comprise glass, ceramic, polymer, metal or combinations thereof. The composition of the frangible material 36 may be selected to have a particular collapse strength which will determine the pressure at which the pressure actuated collapsing capsules 34 rupture, implode or collapse.
  • the wall thickness of the frangible material 36 and the density of the pressure actuated collapsing capsules 34 may also be varied to increase or decrease the pressure at which the pressure actuated collapsing capsules 34 rupture, implode or collapse.
  • the frangible material 36 may be coated with a strengthening material 40 to increase the pressure at which the pressure actuated collapsing capsules 34 rupture, implode or collapse.
  • the strengthening material 40 may comprise glass, ceramic, polymer, metal or combinations thereof.
  • the wall thickness of the strengthening material 40 may also be varied to increase or decrease the pressure at which the pressure actuated collapsing capsules 34 rupture, implode or collapse.
  • the pressured operating fluid 30 can be optimized to mitigate a large range of overpressure conditions within a subterranean containment space in a subterranean well.
  • it is desirable to establish an upper pressure limit within a subterranean containment space by filling at least a portion of the subterranean containment space with pressured operating fluid 30 having a composition of pressure actuated collapsing capsules 34 that have uniform collapse pressures. All or a majority of the pressure actuated collapsing capsules 34 may be designed to rupture, collapse or implode as pressure in a subterranean containment space approaches the upper- pressure limit.
  • pressure actuated collapsing capsules 34 that have nonuniform or graduated collapse pressures to accommodate varying over-pressure conditions.
  • a percentage of pressure actuated collapsing capsules 34 may be designed to rupture collapse or implode at two or more operating pressures within a subterranean containment space.
  • the pressure actuated collapsing capsules 34 may have a collapse pressure less than or equal to 1000 psi of one another.
  • the pressure actuated collapsing capsules 34 may have a collapse pressure of greater than 1000 psi of one another.
  • the pressure actuated collapsing capsules may be glass, ceramic, polymer or metal encased microspheres 34, such as those manufactured by 3M
  • the microspheres 34 may be designed to rupture, implode or collapse when pressure exceeds a predetermined limit.
  • the microspheres 34 may be designed to have a substantially uniform collapse pressure, such that the majority of microspheres 34 fail or collapse at the same pressure.
  • the pressured operating fluid 30 may be tailored to provide overpressure protection above a predetermined pressure limit with the use of a minimum quantity, weight or concentration of microspheres 34.
  • Exemplary collapse pressures of glass, ceramic, polymer and/or metal encased microspheres 34 include, but are not limited to, 250 psi, 1000 psi. 2000 psi, 3000 psi, 4000 psi, 6000 psi, 10,000 psi and greater than 10,000 psi.
  • the pressure actuated collapsing closed capsules are pozzolan or glass encased microspheres 34 provided from the waste stream of a coal-fired power plant.
  • Hollow pozzolan or glass encased microspheres 34 known as floaters or cenospheres are formed in the coal burning process of coal-fired power plants.
  • Cenospheres collect on the surface of disposal ponds where waste fly ash is deposited as part of the waste stream of a coal-fired power plant.
  • Cenospheres are essentially thin-walled pozzolan or glass encased microspheres with a similar composition of fly ash.
  • Pozzolan or glass encased microspheres 34 produced from cenospheres are cheaper than manufactured microspheres 34.
  • Pozzolan or glass encased microspheres 34 produced from cenospheres also have non-uniform or variable collapse pressures.
  • a pressured operating fluid 30 having pozzolan or glass encased microspheres 34 that have non-uniform or graduated collapse pressures it is desirable to introduce a pressured operating fluid 30 into a plurality of subterranean containment spaces in a plurality of subterranean zones having dissimilar temperatures and pressures at varying depths within the subterranean well.
  • the plurality of subterranean containment spaces may be at least partially filled with a pressured operating fluid 30 having a composition of pozzolan or glass encased microspheres 34 that have non-uniform or graduated collapse pressures to accommodate thermal expansion of downhole fluids at varying temperatures and pressures within each subterranean zone.
  • pozzolan or glass encased microspheres 34 produced from cenospheres rupture, implode or collapse between 8000 psi and 10,000 psi.
  • pozzolan or glass encased microspheres 34 produced from cenospheres rupture, implode or collapse between 10,000 psi and 12,000 psi.
  • Tables I through III provide example embodiments of pressured operating fluids having glass encased microspheres suspended in water. The addition of a negligible volume of polymer to aid in suspension of microspheres was assumed. A constant volume subterranean containment space was assumed. The well temperature was increased to cause thermal expansion of the pressured operating fluid.
  • Table I provides the predicted collapse percentage of glass encased microspheres suspended in three operating fluids heated to final temperatures of 126.7°C, 182.2°C, 237.8°C and 293.3°C.
  • the percentage of glass encased spheres collapsing at a given temperature is an indication of the volume change necessary to accommodate the thermal expansion of the water present in the pressured operating fluid.
  • Operating Fluid 1 contains 1 kg of water and 0.2 kg of 3000 psi collapse rated glass encased microspheres.
  • Operating Fluid 2 contains 1 kg of water and 0.3 kg of 3000 psi collapse rated glass encased microspheres.
  • Operating Fluid 3 contains 1 kg of water and 0.4 kg of 3000 psi collapse rated glass encased microspheres.
  • Table II provides the predicted collapse percentage of glass encased microspheres suspended in three operating fluids heated to final temperatures of 126.7°C, 182.2 0 C, 237.8°C and 293.3 0 C.
  • the percentage of glass encased spheres collapsing at a given temperature is an indication of the volume change necessary to accommodate the thermal expansion of the water present in the pressured operating fluid.
  • Operating Fluid 1 contains 1 kg of water and 0.2 kg of 6000 psi collapse rated glass encased microspheres.
  • Operating Fluid 2 contains 1 kg of water and 0.3 kg of 6000 psi collapse rated glass encased microspheres.
  • Operating Fluid 3 contains 1 kg of water and 0.4 kg of 6000 psi collapse rated glass encased microspheres. An initial temperature of 26 0 C was assumed. At temperatures approaching and above 25O 0 C the percentage of microsphere collapse necessary to accommodate the thermal expansion of the pressured operating fluid substantially increases. The theoretical percentage of microsphere collapse in Operating Fluid 1 is 99% at 293.3°C. Therefore, a greater composition of microspheres must be suspended in Operating Fluid 1 to accommodate the potential thermal expansion and resulting over-pressure created at temperatures above 293.3 0 C.
  • Table III provides the predicted collapse percentage of glass encased microspheres suspended in three operating fluids heated to final temperatures of 126. TC, 182.2°C, 237.8°C and 293.3 0 C.
  • the percentage of glass encased spheres collapsing at a given temperature is an indication of the volume change necessary to accommodate the thermal expansion of the water present in the pressured operating fluid.
  • Operating Fluid 1 contains 1 kg of water and 0.2 kg of 10,000 psi collapse rated glass encased microspheres.
  • Operating Fluid 2 contains 1 kg of water and 0.3 kg of 10,000 psi collapse rated glass encased microspheres.
  • Operating Fluid 3 contains 1 kg of water and 0.4 kg of 10,000 psi collapse rated glass encased microspheres.
  • FIG. 3 illustrates an exemplary system for protecting a containment space 218 in an annulus 210 of a subterranean well 200 from over-pressure according to one embodiment.
  • a plurality of casing strings including an inner casing string 204 and an outer casing string 206 are disposed in the wellbore 202.
  • the inner annulus 208 between the inner casing string 204 and the wellbore wall 212 is filled with cement 214 below the mud line 216.
  • the outer annulus 210 between the outer casing string 206 and the wellbore wall 212 is filled with cement 214 below the mud line 216.
  • subterranean pressured fluid receiving containment spaces 218 form in the inner annulus 208 and the outer annulus 210 between the cement 214 and the mud line 216. Downhole fluids may become trapped in subterranean containment spaces 218 during drilling, completion, production, injection or other well operations. [0036] If trapped downhole fluids are heated while in the subterranean containment spaces
  • a pressured operating fluid 220 having a mixture of substantially incompressible liquid and pressure actuated collapsing capsules may be pumped or circulated into the subterranean containment spaces 218 to prevent casing collapse.
  • the pressure actuated collapsing capsules rupture, implode or collapse when the pressure in the subterranean containment space 218 exceeds a predetermined limit, thus releasing pressure in the containment space 218.
  • the pressured operating fluid 220 may be circulated into subterranean containment spaces 218 to prevent casing collapse before, during and/or after cement is circulated into the inner annulus 208 or outer annulus 210 of the wellbore 202.
  • the pressured operating fluid 220 may also be circulated into subterranean containment spaces 218 as part of the cement 214.
  • FIGS. 4A through 4F illustrate an exemplary system for protecting a subterranean containment space 320 in the annulus 306 of a subterranean well 300 from over-pressure according to another embodiment.
  • a two stage cement process is used to secure well casing 308 to the wellbore wall 304.
  • Cement 318 is pumped or circulated into the first stage 324 through the inner diameter of the well casing 308 and back up the annulus 306 near or above a stage tool 310.
  • Pressure may be applied to the wellbore 302 through the inner diameter of the well casing 308 to open the stage tool 310.
  • An opening dart 312 may also be dropped into the well casing 308 on top of the stage tool 310 before pressure is applied to the wellbore 302 to open the stage tool 310. Once the stage tool 310 is opened, the annulus 306 above the tool 310 is circulated clean back to the surface.
  • a first stage plug 314 is launched into the well casing 308 to plug off the first stage 324.
  • Cement 318 is circulated into the second stage 322 through the inner diameter of the well casing 308 and up the annulus 306 of the wellbore 302.
  • a displacement plug 316 may be launched into the well casing 308 to further facilitate displacement and circulation of cement 318 into the annulus 306.
  • spaces, gaps or voids do not form in the annulus 306 in the first stage 324 or the second stage 322 during circulation of cement 318.
  • subterranean containment spaces 320 including gaps, voids and cavities are often created due to lack of volume or lost circulation of cement 318 in the first stage 324 or second stage 322. Downhole fluids may become trapped in subterranean containment spaces 320 in first stage 324, the second stage 322 or between the first stage 324 and the second stage 322 of the annulus 306. [0039] If temperature in the well 300 increases substantially during production of hotter fluids, such as oil, gas, geothermal water, brine and/or steam, thermal expansion of trapped fluid can cause the casing 308 to collapse.
  • hotter fluids such as oil, gas, geothermal water, brine and/or steam
  • a pressured operating fluid 326 having a mixture of substantially incompressible liquid and pressure actuated collapsing capsules may be pumped or circulated into the subterranean containment spaces 320 in the first stage 324, the second stage or between the first stage 324 and the second stage 322 of the annulus 306.
  • the pressure actuated collapsing capsules rupture, implode or collapse when the pressure in the subterranean containment space 320 exceeds a predetermined limit, thus accommodating thermal expansion of fluid in the subterranean containment space 320.
  • the pressured operating fluid 326 may be circulated into subterranean containment spaces 320 to prevent casing collapse before, during and/or after cement 318 is circulated into the first stage 324 or second stage 322 of the annulus 306.
  • the pressured operating fluid 326 may also be circulated into subterranean containment spaces 320 as part of the cement 318.
  • FIGS. 5A through 5E illustrate an subterranean containment system for protecting a downhole packer 406 from over-pressure according to one embodiment.
  • a downhole packer 408 including an expandable bladder 412 and packer body 410 is positioned within a wellbore 400.
  • the expandable bladder 412 is attached to the packer body 410 which includes port sleeves 416, sleeve receiving apertures 418 and inflation ports 420 in fluid communication with the expandable bladder 412 attached thereto.
  • the expandable bladder 412 is positioned in the wellbore annulus 404 between a tubular 406 and the wellbore wall 402.
  • the tubular 406 may be well casing, casing liner, drill pipe, production conduit or other downhole tubular known in the art.
  • a dart seat 414 may be positioned inside the tubular 406 and/or attached to the packer body 410.
  • a seating dart 422 is launched into the tubular 406 to plug the dart seat 414.
  • Pressure is applied to the well packer 408 by pumping or circulating pressured operating fluid 424 having a mixture of substantially incompressible liquid and pressure actuated collapsing capsules through the tubular 406.
  • the pressure drives the port sleeves 416 into the sleeve receiving apertures 418, causes the inflation ports 420 to align and permits the pressured operating fluid 424 to fill the expandable bladder 412.
  • the inflated bladder 412 forms a seal in the annulus 404 between the tubular 406 and the wellbore wall 402. After the downhole packer 408 is filled, any additional pressure applied to the packer 408 through the tubular 406 will cause the port sleeves 416 to withdraw from the sleeve receiving apertures 418 and close the inflation ports 420.
  • the seating dart 422 may also be pushed through the dart seat 414 by applying pressure to the tubular 406.
  • the inflated downhole packer 408 provides hydraulic isolation in the annulus 404 to allow for pumping or circulation of fluids below the packer 408. Temperature in the well may increase during production of hotter fluids, such as oil, gas, geothermal water, brine and/or steam. The temperature of the well and fluids therein may also increase in a geothermal well approaching the geostatic temperature.
  • the expandable bladder 412 of the downhole packer 408 can be at least partially filled with the pressured operating fluid 424 to protect the expandable bladder 412 from over-pressure.
  • Pressure actuated collapsing capsules suspended in the pressured operating fluid 424 rupture, implode or collapse when the pressure in the expandable bladder 412 exceeds a predetermined limit, thus accommodating for thermal expansion of fluids in the expandable bladder 412.
  • the wellbore 400 and packer 408 may be cooled with cooling fluid 426 to cause contraction of the pressured operating fluid 424 in the expandable bladder 412.
  • the volume of the pressured operating fluid 424 within the expandable bladder 412 may be reduced substantially (e.g. 10-20 percent reduction in volume) by cooling the pressured operating fluid 424 after a portion of the pressure actuated collapsing capsules have ruptured, imploded or collapsed. This allows easy removal of the packer 408 from the wellbore 400 without the need to drill out the packer 408 or remove the pressured operating fluid 424 from the expandable bladder 412.
  • FIG. 6 illustrates an exemplary system for protecting a subterranean containment space in a geothermal well 500 from over-pressure according to one embodiment.
  • a geothermal well 500 is created by drilling a wellbore 502 into a geothermal formation 504 capable of producing heat from fractures 506 within the formation 504.
  • the wellbore wall 524 is lined with casing 510 and a production conduit 512 is positioned within the wellbore 504 interior of the casing 510.
  • An annulus 508 may exist between the casing 510 and the wellbore wall 524 or between the casing 510 and the production conduit 512.
  • a downhole packer 514 including an expandable bladder 516 may be positioned in the well 500 to provide hydraulic or zonal isolation within the annulus 508 between the casing 510 and the wellbore wall 524 or between the casing 510 and the production conduit 512.
  • Annular cavities 518 may form in the annulus 508 between the casing 510 and the wellbore wall 524 or between the casing 510 and the production conduit 512 during drilling, completion, production and/or other well operations. Downhole fluids may become trapped within subterranean containment spaces including, but not limited to, an annular cavity 518, an expandable packer bladder 516, or a naturally occurring fracture 506 in the formation 504.
  • Geothermal wells completed in deep granite basement rock can have well temperatures greater than 300 0 C. The thermal expansion of water or other substantially incompressible fluids used in well operations could cause severe damage to the geothermal well and formation at temperatures as low as 100 0 C.
  • the pressured operating fluids having a mixture of substantially incompressible liquid 32 and pressure actuated collapsing capsules 32 herein disclosed are capable of accommodating thermal expansion and resulting over-pressure in subterranean containment spaces.
  • a pressured operating fluid 522 comprising a mixture of substantially incompressible liquid and pressure actuated collapsing capsules may be pumped or circulated into annular cavities 518, the expandable packer bladder 516, or naturally occurring fractures 506 in the formation 504.
  • the pressure actuated collapsing capsules rupture, implode or collapse when the pressure in the subterranean containment space exceeds a predetermined limit, thus accommodating thermal expansion of liquid in the subterranean containment space.
  • Example embodiments have been described hereinabove regarding improved systems and methods for use of microspheres suspended in a thermally expanding fluid. Various modifications to and departures from the disclosed example embodiments will occur to those having ordinary skill in the art. The subject matter that is intended to be within the spirit of this disclosure is set forth in the following claims.

Abstract

La présente invention concerne des systèmes et des procédés pour l’utilisation de capsules aplatissables à actionnement par pression, suspendues dans un fluide à dilatation thermique dans un espace de confinement souterrain. Selon un mode de réalisation, un système comprend un espace de confinement souterrain de réception de fluide sous pression (106) situé dans un puits forage d’un puits souterrain (102) et un fluide fonctionnant sous pression (108) qui remplit au moins une partie de l’espace de confinement. Le fluide fonctionnant sous pression comprend un mélange de liquide sensiblement incompressible et des capsules aplatissables à actionnement par pression. Au moins une partie des capsules aplatissables à actionnement par pression implose lorsque la pression dans l’espace de confinement dépasse une limite prédéterminée.
PCT/US2009/042137 2008-04-30 2009-04-29 Système et procédé pour l’utilisation de capsules aplatissables à actionnement par pression, suspendues dans un fluide à dilatation thermique dans un espace de confinement souterrain WO2009134902A1 (fr)

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US9062240B2 (en) 2010-06-14 2015-06-23 Halliburton Energy Services, Inc. Water-based grouting composition with an insulating material

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